Evaluation of Coal and Natural Gas With Carbon Capture as Proposed Solutions to Global Warming, Air Pollution, and

Energy Security

In Jacobson, M.Z., 100% Clean, Renewable Energy and Storage for Everything, Cambridge

University Press, New York, 427 pp., 2020 https://web.stanford.edu/group/efmh/jacobson/WWSBook/WWSBook.html

January 7, 2020

Contact: Jacobson@stanford.edu; Twitter @mzjacobson Summary Coal and natural gas with carbon capture and storage (CCS) and use (CCU) have been advertised as zero-carbon sources of electric power that should be implemented as solutions to global warming, air pollution, and energy security. Natural gas has also been proposed as a bridge fuel between coal and renewables. This section evaluates these claims. Neither coal nor natural gas with carbon capture is remotely close to zero carbon. Based on data, they reduce only ~10.8% carbon equivalent emissions (CO2e) over a 20-year time frame and ~20% over a 100-year time frame. At the same time, they increase air pollution and land degradation compared with no carbon capture by 25 to 50 percent. The use of the captured CO2 for enhancing oil recovery causes even greater damage. Finally, the cost of installing carbon capture equipment is large. Here are additional specific findings: • There is no low-carbon, let alone zero-carbon coal or natural gas power plant with carbon capture

in existence. • In the Petra Nova coal with carbon capture plant in Texas, only 10.8 percent (rather than 90%) of

the intended CO2 emissions are reduced over a 20-year time frame and only 20 percent are reduced over a 100-year time frame.

• These emission savings may be offset fully by emissions from the oil recovered with the CO2. • Spending on carbon capture rather than wind replacing either fossil fuels or bioenergy always

increases total social cost substantially. No improvement in capture equipment can change this conclusion, since carbon capture always incurs an equipment cost never incurred by wind, and carbon capture never reduces, instead mostly increases, air pollution and mining.

• New natural gas with CCS/U produces 27-100 times the 100-year CO2e as new onshore wind. • New coal with CCS/U produces 33-211 times the 100-year CO2e emissions as new onshore wind. • Without carbon capture, open cycle natural gas turbines and combined cycle natural gas turbines

cause 2.8 and 2.3 times, respectively, the global warming per unit energy over a 20-year time frame as a coal plant and only 8-28 percent less warming over 100 years than a coal plant.

• The reason is the higher SO2 and NOx and lower CH4 emissions from coal. The higher SO2, NOx, and particulate emissions from coal result in coal causing about five times the premature mortality as gas.

• As such, natural gas is not a bridge fuel. • Instead, coal and gas are both horrendous for climate, health, and land although coal causes

greater health problems. • In comparison, wind, water, and solar power substantially address nearly all climate, health, and

energy security problems.

3.1. Why Not Use Natural Gas as a Bridge Fuel? Natural gas is a colorless, flammable gas containing a mass (mole) fraction of about 88.5 (93.9) percent methane plus smaller amounts of ethane, propane, butane, pentane, hexane, nitrogen, carbon dioxide, and oxygen (Union Gas, 2018). It is often found near petroleum deposits. It is usually either combusted in a gas turbine that is coupled with a generator to produce electricity or combusted in a burner to produce either building heat or high-temperature industrial heat. Because natural gas is not very dense, it can be stored on its own only in a large container. As such, natural gas is often compressed or liquefied for transport and storage. Compressed natural gas (CNG) is natural gas compressed to less than 1 percent of its gas volume at room temperature. Liquefied natural gas (LNG) is natural gas that has been cooled to -162 oC, the temperature at which it condenses to a liquid at ambient pressure. LNG has a volume that is 1/600th the volume of the original gas. Both CNG and LNG can be sent through pipelines, although different pipelines are needed for each. CNG and LNG can also be stored and used directly in automobiles that are designed to run on them. CNG and LNG can further be transported by truck or bus with a special fuel tank and can be stored at a power plant for backup use when pipeline gas is not available. In addition, pipeline CNG is often converted to LNG at a marine export terminal, put on a tanker ship with super-cooled cryogenic tanks, and shipped overseas. At the import terminal, it is re-gasified and piped to its final destination -- either a power plant, industrial company, or company that transmits and distributes it to buildings for heating or other purposes. Natural gas is obtained from underground conventional wells containing both oil and natural gas or by hydraulic fracturing. Hydraulic fracturing (fracking) is the process by which natural gas is extracted from shale rock formations instead of wells. Shale is sedimentary rock composed of a muddy mix of clay mineral flakes and small fragments of quartz and calcite. Large shale formations containing natural gas can be found in eastern North America, close to population centers, among many other locations worldwide. In the U.S., about 67 percent of natural gas in 2015 was extracted from shale rock (EIA, 2016b). Extraction of natural gas from shale requires large volumes of water, laced with chemicals, forced under pressure to fracture and re-fracture the rock to increase the flow of natural gas. As the water returns to the surface over days to weeks, it is accompanied by methane that escapes to the air. As such, more methane leaks occur during fracking than during the drilling of conventional gas wells (Howarth et al., 2011, 2012; Howarth, 2019). Methane also leaks during the transmission, distribution, and processing of natural gas. For electricity production, natural gas is usually used in either an open cycle gas turbine (OCGT) or a combined cycle gas turbine (CCGT). In an OCGT, air is sent to a compressor, and the compressed air and natural gas are both sent to a combustion chamber, where the mixture is burned. The hot gas expands quickly, flowing through a turbine to perform work by spinning the turbine’s blades. The rotating blades turn a shaft connected to a generator, which converts a portion of the rotating mechanical energy to electricity. The main disadvantage of an OCGT is that that the exhaust contains a lot of waste heat that could otherwise be used to generate more electricity. A CCGT routes that heat to a heat recovery steam generator, which boils water with the heat to create steam. The steam is then sent to a steam turbine connected to the generator to generate 50 percent more electricity than the OCGT alone. Thus, a CCGT produces about 150 percent the electricity as an OCGT with the same input mass of natural gas thus carbon dioxide emissions in each case.

On the other hand, the ramp rate of an OCGT is 20 percent per minute, which is 2 to 4 times that of a CCGT (5 to 10 percent per minute) (Table 2.1). Thus, the less efficient OCGT, which also releases more CO2 per unit electricity generated (Table 3.1), is more useful for filling in short-term gaps in supply on the grid than is a CCGT. It has long been suggested that natural gas could be used as a bridge fuel between coal and renewables (e.g., MIT, 2011). The two main arguments for this suggestion are (1) natural gas emits less carbon dioxide equivalent emissions per unit energy produced (CO2e – Section 1.2.3.5) than coal and (2) natural gas electric power plants are better suited to be used with intermittent renewables than coal. However, the justifications for using gas as a bridge fuel are incorrect and insufficient. Natural gas is not recommended for use together with WWS technologies for multiple reasons. These are discussed in the following sections. 3.1.1. Climate Impacts of Natural Gas Versus Other Fossil Fuels When used in an electric power plant, natural gas substantially increases, rather than decreases, global warming (by increasing CO2e) compared with coal over a 20-year time frame. The difference over 100 years, while more favorable to gas, is relatively small (Table 3.1). Regardless, CO2e emissions (and health-affecting air pollutant emissions) from both gas and coal are much larger than are those from WWS technologies, so spending money on natural gas or coal represents an opportunity cost relative to spending the same money on WWS. Over a 20-year time frame, the CO2e from using natural gas with a CCGT or an OCGT is 2.3 and 2.8 times, respectively, that using coal (Table 3.1). Over a 100-year time frame, the CO2e from a natural gas OCGT is only 8 percent less than that of coal, and the CO2e from a natural gas CCGT is only 28 percent less than that of coal. The fact that natural gas causes far more global warming than coal over a 20-year time frame is a concern because of the severe damage global warming is already causing that will only be made worse over the next two decades, including the triggering of some difficult-to-reverse impacts, such as the complete melting of the Arctic ice. The reasons that the CO2e of natural gas exceeds that of coal over 20 years and is close to that of coal over 100 years are as follows. First, although natural gas combustion in an OCGT or CCGT emits only 60 or 45 percent, respectively, of the CO2 per kilowatt-hour (kWh) of coal combustion, natural gas leaks during the mining and transport of natural gas emit similar or more CH4 than do CH4 leaks during coal mining. This is an issue, because CH4 has a high, positive 20- and 100-year GWP (Table 1.2). As such, the leaked CH4 from natural gas mining and transport contributes substantially to the CO2e of natural gas. Second, and more important, coal combustion emits more NOx and SO2 per kWh than does natural gas combustion (Table 3.1), and NOx and SO2 both produce cooling aerosol particles, which offset or mask much of global warming, particularly over a 20-year time frame (Figure 1.2). The cooling impacts of these particles are through their direct reflection of sunlight back to space and their enhancement of cloud thickness. Thicker clouds reflect more sunlight back to space. As such, NOx and SO2, which are both short-lived, have high negative GWPs over both 20 years and 100 years (Table 3.1).

Howarth et al. (2011, 2012) identified the importance of methane leaks, particularly natural gas fracking of shale gas on the CO2e emissions of natural gas versus coal on a 20- versus 100-year lifetime. Wigley (2011), for one, estimated the cooling impact of SO2, but not NOx, when comparing CO2e from coal versus natural gas power plants. Table 3.1. Comparison of 20- and 100-year lifecycle global CO2 equivalent (CO2e) emissions from coal versus natural gas used in either an open cycle gas turbine (OCGT) or a combined cycle gas turbine (CCGT) for electricity generation. Coal Natural Gas

Open Cycle Gas Turbine Natural Gas

Combined Cycle Gas Turbine Chemical (X) 20-y

GWP 100-y GWP

Emis. factor (g-X/ kWh)

20-y CO2e

(g-CO2e /kWh)

100-y CO2e

(g-CO2e /kWh)

Emis. factor (g-X/ kWh)

20-y CO2e

(g-CO2e /kWh)

100-y CO2e

(g-CO2e /kWh)

Emis. factor (g-X/ kWh)

20-y CO2e

(g-CO2e /kWh)

100-y CO2e

(g-CO2e /kWh)

aCO2-upstream 97.2 97.2 54 54 54 54 bCH4-leak 86 34 4.1 353 140 4.35 374 148 3.26 280 111 cCO2-plant 1 1 905 905 905 540 540 540 404 404 404 dBC+OM-plant 3,100 1,550 0.045 141 70 0.0003 0.93 0.47 0.0003 0.93 0.47 cNOx-N-plant -560 -159 0.23 -129 -37 0.15 -84 -24 0.015 -8.4 -2.4 cSO2-S-plant -1,400 -394 0.75 -1,050 -393 0.005 -7 -2 0.0015 -2.1 -2 Total 317 782 878 716 728 565 All 20- and 100-year GWPs are from Table 1.2. Each CO2e, except for upstream values, is the product of an emission

factor and a GWP. aUpstream CO2 emissions from coal mining, processing, and transport are 27 g-CO2/MJ, or 97.2 g-CO2/kWh and from

natural gas are 15 g-CO2/MJ = 54 g-CO2/kWh (Howarth, 2014). bFor coal, the 100-year CO2e from CH4 leaks is estimated from Skone (2015), Slide 17. The emission factor in the

present table is then derived from that number and the 100-year GWP of CH4 in the present table. The 20-year CO2e is then calculated from the emission factor and the 20-year GWP. For natural gas, the CH4-leak emission factors in the present table are obtained by multiplying the mass of CH4 required per kWh of electricity by L/(1-L), where L is the fractional leakage rate of methane between mining and use in a power plant. The mass of CH4 required per kWh for a natural gas turbine is the CO2 combustion emissions from the turbine (present table) multiplied by the ratio of the molecular weights of CH4:CO2 (16.04276 g/mol:44.0098 g/mol) and by the mole fraction of natural gas that consists of methane (0.939) (Union Gas, 2018). The results are 184.8 g-CH4/kWh-electricity for open cycle and 138.3 g-CH4/kWh-electricity for combined cycle. The overall U.S. methane leakage rate, from shale gas, which includes leaks from drilling and from pipe transmission and distribution to electric power plants, industrial facilities, homes, and other buildings, may be ~3.5 percent (Howarth, 2019). Shale gas was about 2/3 of the U.S. natural gas production in 2015 (EIA, 2016b). The leakage rate all natural gas (shale gas plus conventional gas) for only drilling and transmission to large facilities may be ~2.3 percent (Alvarez et al., 2018). This number is used in this table, which is for electric power plant generation.

cEmission factors from Figure 4 of de Gouw et al. (2014) for 2012 U.S. plants; For NOx-N, emission factors for NOx-NO2 were multiplied by the ratio of the molecular weight of N to that of NO2. For SO2-S, emission factors for SO2 were multiplied by the ratio of the molecular weight of S to that of SO2.

dThe emission factor of BC+OM for coal and natural gas were obtained from Bond et al. (2004) assuming, for coal, pulverized coal and a mix between hard and lignite coal.

Neither natural gas nor coal is recommended in a 100 percent WWS world because, among other reasons, the natural gas lifecycle 100-year CO2e for electricity generation (565 to 716 g-CO2e/kWh) (Table 3.1) is on the order of 56 to 72 times that of wind (~10 g-CO2e/kWh) (Table 3.5), and the 100-year coal CO2e (~780 g-CO2e/kWh) is about 78 times that of wind. Similarly, both coal and gas produce much more air pollution than do WWS sources (Section 3.1.2). The CO2e emissions from natural gas versus other fossil fuels are higher for heating and transportation than for electricity. For building heat and industrial process heat, for example, natural gas offers less efficiency advantage over oil or coal than it does for electricity generation. As such, after accounting for all chemical emissions and their respective global warming potentials, natural gas may cause greater long-term global warming than does oil or coal for heating.

With respect to transportation fuels, the carbon dioxide equivalent emissions of natural gas may also exceed that of oil, since the efficiency of natural gas used in transportation is similar to that of oil. Thus, when methane leaks are added in, natural gas causes more overall warming than oil (Alvarez et al. 2012). In sum, in terms of climate, natural gas causes greater global warming than other fossil fuels over 20 years across all applications. Over a 100-year time frame, natural gas causes similar or less warming than coal used for electricity generation and greater warming than oil for heating and transportation over 100 years. All fossil fuels emit 1.5 to 2 orders of magnitude the CO2e as WWS sources. 3.1.2. Air Pollution Impacts of Natural Gas Versus Coal and Renewables Whereas natural gas causes more CO2e emissions than coal over 20 years and a similar or slightly less level over 100 years, coal emits more health-affecting air pollutants than does natural gas, which is the main reason it has a lower CO2e over 20 years than does natural gas. Nevertheless, both natural gas and coal are much worse for human health than are WWS technologies, which emit no air pollutants during their operation, only during their manufacture and decommissioning. Such WWS emissions will disappear to zero as all energy transitions to WWS since even manufacturing will be powered by WWS at that point. Table 3.2 provides U.S. emissions from all natural gas and coal uses in the United States in 2008. The table indicates that natural gas production and use in the U.S. emitted more CO, volatile organic carbon (VOC), CH4, and ammonia (NH3) than coal production and use, whereas coal emitted more NOx, SO2, and particulate matter smaller than 2.5- and 10-µm in diameter (PM2.5, PM10). Thus, both fuels resulted in significant air pollution, although the higher SO2, NOx, and particulate matter emissions from coal resulted in overall greater air pollution health problems from coal than natural gas. Table 3.2. 2008 U.S emissions from natural gas and coal (metric tonnes/y). Bold indicates higher overall emissions between coal and natural gas (NG).

Coal All Uses

NG All Uses

CO 680 900 VOC 40 1,130 CH4 5 310 NH3 11 54 NOx 2,800 1,540 SO2 7,600 123 PM2.5 290 61 PM10 420 71

Source: U.S. EPA (2011). VOCs exclude methane. The methane emissions from the EPA inventory are likely underestimated (e.g., Alvarez et al., 2018). Most SO2 and NOx emissions evolve to sulfate and nitrate aerosol particles, respectively. Natural gas also emits NOx, but less so than does coal (Tables 2.6 and 2.7). Natural gas, on the other hand, emits much less SO2 than does coal (Tables 2.6 and 2.7). Aerosol particles, including those containing sulfate and nitrate formed from gases in the atmosphere, and those emitted directly, cause 90 percent of the 4 to 9 million air pollution deaths that occur annually worldwide (Section 1.1.1). As such, coal in particular, but also natural gas, causes significant health damage. Model simulations over the United States with the emission data from Table 3.2 suggests that emissions from all natural gas sources may cause 5,000 to 10,000 premature mortalities each year in the U.S. from air pollution (Jacobson et al., 2015a). Coal-related emissions may cause 20,000 to 50,000 premature mortalities in the U.S. Many of the remaining premature mortalities are due to pollution associated with oil

(e.g., traffic exhaust, oil refinery evaporation), biofuels for transportation, and wood smoke emissions from open fires, fireplaces, and cooking. In sum, coal causes more mortalities than does natural gas, but both coal and gas cause far more mortalities than do WWS technologies. The combination of the much higher CO2e emissions and premature mortalities due to natural gas than WWS technologies renders natural gas not an option as a bridge fuel. 3.1.3. Using Natural Gas for Peaking or Load Following Another argument for using natural gas as a bridge fuel is that it can be used in a load-following or peaking plant (defined in Section 2.4), and WWS technologies will need load-following or peaking plants that use natural gas to back them up when not enough wind or solar is available. Whereas natural gas plants can help with peaking and load following, they are not needed (Section 8.2.1). Other types of WWS electric power storage options available include CSP with storage, hydroelectric dam storage, pumped hydropower storage, stationary batteries, flywheels, compressed air energy storage, and gravitational storage with solid masses (Section 2.7). As of 2019, the cost of a system consisting of wind and solar plus batteries costs less than using natural gas. For example, a Florida utility is replacing two natural gas plants with a combined solar-battery system due the lower cost of the latter (Geuss, 2019). More important, a 100 percent WWS world involves electrifying or providing direct heat for all energy sectors, where the electricity or heat comes from WWS. Such a transition allows heat, cold, and hydrogen storage to work together with demand response to facilitate matching electric power demand with supply on the grid while also satisfying heat, cold, and hydrogen demands minute by minute at low cost. Chapter 8 discusses this issue in detail. 3.1.4. Land Required for Natural Gas Infrastructure The continuous use of natural gas for electricity and heat results in the continuous and cumulative degradation of land for as long as the gas use goes on. Wells must be dug, and pipes laid every year to supply a world thirsty for gas. When gas wells become depleted, new wells much be drilled. Allred et al. (2015) estimate that 50,000 new natural gas wells are drilled each year in North America alone to satisfy gas demand. The land area required for the well pads, roads, and storage facilities of these new wells amounts to 2,500 km2 of additional land consumed per year (Allred et al., 2015). Once a gas well is depleted, it is sealed and abandoned, and a portion of the abandoned land cannot be used for any other purpose. The natural gas infrastructure also requires land for underground and aboveground pipes, power plants, fueling stations, and underground storage facilities. The flammability of natural gas further results in explosions in homes and urban areas that have had fatal consequences. Table 3.3 shows the estimated land required for the entire fossil fuel and nuclear infrastructure in California and the United States. The table indicates that the fossil fuel infrastructure currently takes up about 1.3 percent of the United States land area and 1.2 percent of California’s land area. Whereas all fossil fuels contribute to this land area degradation, natural gas’ share is growing due to the phase out of coal and the growth of natural gas, particularly of hydraulically fracked gas. The damage due to fracking includes damage not only to the landscape but also to groundwater, in which fracked natural gas often leaks. Additional damage occurs to roads, which much carry heavy trucks associated with natural gas development. Gas flaring is another form of local environmental degradation, as the flaring emits soot (containing black carbon), which warms the air, evaporates clouds, and melts snow. Table 3.3. Estimated land areas required for the fossil fuel and nuclear infrastructure in California and the United States circa 2018.

California United States

Area per installation

(km2)

Number Area (km2)

Number Area (km2)

aActive oil and gas wells 0.05 105,000 3,327 1.3 million 65,000 bAbandoned oil wells 0.00005 225,000 6.6 2.6 million 128.5 bAbandoned gas wells 0.000025 48,000 0.7 550,000 13.8 cCoal mines 50 0 0 680 34,000 dOil refineries 7.28 17 124 135 983 eKilometers of oil pipeline 0.006 4,800 29 258,000 1,550 eKilometers of gas pipeline 0.006 180,000 1,080 2.62 million 15,700 fCoal power plants 1.74 1 1.74 359 626 fGas power plants 0.12 37 4.5 1,820 221 fPetroleum power plants 0.93 0 0 1,080 1,007 fNuclear power plants 14.9 1 14.9 61 911 fOther power plants 0.93 0 0 41 41 gFueling stations 0.0018 10,200 18 156,000 275 hGas storage facilities 12.95 10 130 394 5,102 Total 4,736 126,000 Percent of CA or U.S. 1.2 1.3

aNumber of active oil and gas wells, compressors, and processors from Oil and Gas (2018). The area of each is calculated from the 3 million ha of well pads, roads, and storage facilities required for 600,000 new wells from 2000 to 2012 (Allred et al., 2015).

bThe number of abandoned U.S. oil and gas wells is from U.S. EPA (2017), slide 11. The California number is calculated as the U.S. number multiplied by the California to U.S. ratio of active wells. The area of each abandoned oil well is estimated as 50 m2, and of each gas well, 25 m2 from Jepsen (2018).

cThe number of coal mines is from EIA (2018a). The area per mine is estimated from the total area among all mines from Sourcewatch (2011) divided by number of mines here.

dThe number of oil refineries is from EIA (2018b). The area of each refinery is based on the area of the Richmond, California refinery.

eKilometers of oil and gas pipeline for the U.S. were from BTS (2018); for California were estimated. The area needed for each 1 km of pipeline is estimated to be 6 m (3 m on each side of the pipe) multiplied by 1 km.

fThe numbers of coal, gas, petroleum, nuclear and other power plants are from EIA (2018c). The areas for each coal, gas, and nuclear plant is derived from Strata (2017). For coal, the area includes those for the plant and waste disposal (mining is a separate line in this table). For gas, the area is just for the plant. For nuclear, the area includes the areas required for uranium mining, the plant itself, and waste disposal. The areas required for petroleum and other are an average of that for a coal and gas plant.

gThe number of retail fueling stations in the U.S. is from AFDC (2014) for 2012 and in California, from Statistica (2017) for 2016. The area of a fueling station is estimated from the area of a typical gas station.

fThe number of gas storage facilities is from FERC (2004). The area of a gas storage facility is estimated as that of the Aliso Canyon storage facility.

A transition to 100 percent WWS, on the other hand, eliminates the energy needed continuously to mine, transport, and process fossil fuels and uranium, which amounts to 12.1 percent of all energy worldwide (Table 7.1). Wind, on the other hand, comes right to the turbine, and sunlight comes right to the solar panel. In other words, eliminating all fossil fuels and uranium by switching to WWS will eliminate immediately 12.1 percent of all energy needed worldwide and will prevent the future degradation of land due to the continuous mining of fossil fuels and uranium.

3.2. Why Not Use Natural Gas or Coal with Carbon Capture? Another proposal to help solve the climate problem is to capture the CO2 emitted from a coal or natural gas power plant before the CO2 is released from the exhaust stack. This would be accomplished with carbon capture and sequestration (CCS) equipment added to the plant. However, this solution is poor for four reasons: it increases emissions and health problems of all gases and particles aside from CO2 compared with no CCS, it only marginally reduces CO2, it increases the land degradation from the mining of fossil fuels compared with no CCS, and its high cost prevents more effective climate and pollution mitigation with lower-cost renewables. Carbon capture and sequestration (CCS) is the separation of CO2 from other exhaust gases after fossil fuel or biofuel combustion, followed by the transfer of the CO2 to an underground geological formation (e.g., saline aquifer, depleted oil and gas field, or un-minable coal seam). The remaining combustion gases are emitted into the air or filtered further. Geological formations worldwide may theoretically store up to 2,000 Gt-CO2, which compares with a fossil fuel emission rate in 2017 of about 37 Gt-CO2/y. Another proposed CCS method is to inject the CO2 into the deep ocean. The addition of CO2 to the ocean, however, results in ocean acidification. Dissolved CO2 in the deep ocean eventually equilibrates with CO2 in the surface ocean, reducing ocean pH and simultaneously supersaturating the surface ocean with CO2, forcing some of it back into the air. A third type of sequestration method is to mix captured CO2 with concrete material, trapping the CO2 inside the concrete (Section 2.4.8.2). Carbon capture and use (CCU) is the same as CCS, except that the isolated CO2 with CCU is sold to reduce the cost of the carbon capture equipment. To date, the major application of CCU has been enhanced oil recovery. With this process, CO2 is pumped underground into an oil field. It binds with oil, reducing its density and allowing it to rise to the surface more readily. Once the oil rises up, the CO2 is separated from it and sent back into the reservoir. About two additional barrels of oil can be extracted for every ton of CO2 injected into the ground. Another proposed use has been to create carbon-based fuels to replace gasoline and diesel. The problem with this proposal is that it allows combustion to continue in vehicles. Combustion creates air pollution, only some of which can be stopped by emission control technologies. 3.2.1. Air Pollution Increases and Only Modest Lifecycle CO2e Decreases due to Carbon Capture Whereas carbon capture equipment is nominally expected to capture 85 to 90 percent of the CO2 from a fossil fuel exhaust stream, several factors cause the overall CO2 and CO2e savings due to carbon capture to be much smaller than this but also cause an increase in emissions of health-affecting air pollutants relative to no carbon capture. The reasons for these impacts are summarized as follows:

1) A fossil fuel with carbon capture power plant needs to produce 25 to 50 percent more energy, thus

requires 25 to 50 percent more fuel, to run the carbon capture equipment than does a plant without the equipment (IPCC, 2005, EIA, 2017).

2) Carbon capture equipment does not capture the upstream CO2e emissions resulting from mining, transporting, or processing the fossil fuel used in the plant. Instead, such emissions increase 25 to 50 percent because 25 to 50 percent more fuel is needed. These emissions offset a portion of the captured CO2 from the plant exhaust and increase the air pollution associated with the mining, transporting, and processing of the fuel.

3) The carbon capture equipment does not capture any of the non-CO2 air pollutants from the fossil fuel exhaust. Such pollutants include CO, NOx, SO2, organic gases, mercury, toxins, BC, BrC, fly ash, and other aerosol components, all of which affect health. Instead, those pollutants increase 25 to 50 percent because this much more fossil fuel from the plant is needed to run the CCS equipment.

4) The chance that CO2 sequestered underground leaks increases over time and varies with geological formation.

One way to estimate the climate impact of carbon capture equipment attached to a fossil fuel plant is to examine the plant’s lifecycle emissions before and after the equipment is added. Lifecycle emissions are carbon-equivalent (CO2e) emissions of a technology per unit electric power generation (kWh or MWh), averaged over a 20- or 100-year time frame. The emissions accounted for include those during the construction, operation, and decommissioning of the plant. For a fossil fuel (or nuclear) plant, the operation phase includes mining, transporting, and processing the fuel as well as running the plant equipment, repairing the plant over its life, and disposing of waste (e.g., coal residue or nuclear waste) over its life. Lifecycle CO2e is calculated as the lifecycle emission of CO2 plus the lifecycle emission of each other gas or particle pollutant from the technology multiplied by its respective 20- or 100-year GWP (Table 1.2). Table 3.4 shows theoretical estimates of 20- and 100-year lifecycle CO2e emissions from an average U.S. coal plant, a modern supercritical pulverized coal (SCPC) plant, and a natural gas combined cycle gas turbine (CCGT) plant, each with and without carbon capture. An SCPC plant operates at a high temperature and pressure than a normal coal plant. As such, the efficiency of combustion (electricity production per mass of coal) is higher. The table indicates that, even after carbon capture, the coal SCPC plant still emits 50.4 percent of its CO2e over 20 years and 28.7 percent over 100 years compared with no carbon capture. A natural gas CCGT emits 34 percent of its CO2e over 20 years and 35.4 percent over 100 years compared with no capture. These results reflect the fact that the carbon capture equipment increases the upstream emissions of CO2e due to increasing the fuel needed to be burned in the power plant. The results also reflect the fact that the carbon capture equipment lets 10 to 15 percent of the CO2 emitted by the stack escape. Whereas, these estimates are theoretical, data from a real coal plant before and after carbon capture (Table 3.6) show much lesser removal of CO2e than indicated in the Table 3.4. Table 3.4. Theoretical lifecycle 20-year and 100-year CO2e emissions from average U.S. coal power plants, a supercritical pulverized coal (SCPC) power plant and a natural gas combined cycle gas turbine (CCGT) plant with and without carbon capture. Compare with data from a real carbon capture facility in Table 3.6.

Average U.S. Coal Plant Coal SCPC Plant Natural Gas CCGT Plant No

Carbon Capture

With Carbon Capture

Percent CO2e

Remaining

No Carbon Capture

With Carbon Capture

Percent CO2e

Remaining

No Carbon Capture

With Carbon Capture

Percent CO2e

Remaining 20-y CO2e/kWh

1,316 664 50.4 1,188 599 50.4 896 305 34.0

100-y CO2e/kWh

1,205 346 28.7 965 277 28.7 506 179 35.4

All values are from Skone (2015), except the percent remaining for average U.S. coal was assumed the same as from Coal SCPC, and the CO2e values with carbon capture for average U.S. coal were calculated from the percent remaining and the no carbon capture values. The results in Table 3.4 suggest that carbon capture does not come close to eliminating CO2e emissions from coal or gas power plants. Data from real world projects (Section 3.2.3) indicate even less reduction in CO2e emissions due to carbon capture than Table 3.4 suggests. Further, the lifecycle CO2e emissions from a natural gas or coal plant with carbon capture are not the only emissions associated with a fossil fuel plant. Other important emissions include those that affect human and animal health. Lifecycle emissions can be placed in context only when all relevant climate-affecting emissions or avoided emissions associated with a plant are accounted for and compared with the same from other energy technologies, as discussed next. 3.2.2. Total CO2e Emissions of Energy Technologies Lifecycle emissions are one component of total carbon equivalent (CO2e) emissions. Additional components relevant to fossil fuels with carbon capture include opportunity cost emissions, anthropogenc heat emissions, anthropogenic water vapor emissions, emissions risk due to CO2 leakage, and emissions due to covering or clearing land for energy development. These are discussed next, in turn. 3.2.2.1. Opportunity Cost Emissions Opportunity cost emissions are emissions from the background electric power grid, averaged over a defined period of time (e.g., either 20 years or 100 years), due to two factors. The first factor is the longer time lag between planning and operation of one energy technology relative to another. The second factor is the longer downtime needed to refurbish one technology at the end of its useful life when its useful life is shorter than that of another technology (Jacobson, 2009). For example, if Plant A takes 4 years and Plant B takes 10 years between planning and operation, the background grid will emit pollution for 6 more years out of 100 years with Plant B than with Plant A. The emissions during those additional 6 years are opportunity cost emissions. Such additional emissions include emissions of both health- and climate-affecting air pollutants. Similarly, if Plant A and B have the same planning-to-operation time but Plant A has a useful life of 20 years and requires 2 years of refurbishing to last another 20 year and Plant B has a useful life of 30 years but takes only 1 year of refurbishing, then Plant A is down 2 y / 22 y = 9.1 percent of the time for refurbishing and Plant B is down 1 y / 31 y = 3.2 percent of the time for refurbishing. As such, Plant B is down an additional (0.091 – 0.032) × 100 y = 5.9 years out of every 100 for refurbishing. During those additional years, the background grid will emit pollution with Plant B. Mathematically, opportunity cost emissions (EOC, in g-CO2e/kWh) are calculated as EOC = EBR,H - EBR,L (3.1) where EBR,H are total background grid emissions over a specified number of years due to delays between planning and operation and downtime for refurbishing of the technology with the more delays. EBR,L is the same but for the technology with the fewer delays. Background emissions (for either technology) over the number of years of interest, Y, are calculated as EBR = EG × [TPO + (Y – TPO) × TR / (L+TR)] / Y (3.2) where EG is the emissions intensity of the background grid (g-CO2e/kWh for analyses of the climate impacts and g-pollutant/kWh for analyses of health-affecting air pollutants), TPO is the time lag (in years)

between planning and operation of the technology, TR is the times (years) to refurbish the technology, and L is the operating life (years) of the technology before it needs to be refurbished. Example 3.1. Opportunity cost emissions. What are the opportunity cost emissions (g-CO2e/kWh) over 100 years resulting from Plant B if its planning-to-operation time is 15 years, its lifetime is 40 years, and its refurbishing time is 3 years, whereas these values for Plant A are 3 years, 30 years, and 1 year, respectively? Assume both plants produce the same number of kWh/y once operating, and the background grid emits 550 g-CO2e/kWh. Solution: The opportunity cost emissions are calculated as the emissions from the background grid over 100 years of the plant with the higher background emissions (Plant B in this case) minus those from the plant with the lower background emissions (Plant A). The background emissions from Plant B are calculated from Equation 3.2 with EG=550 g-CO2e/kWh, Y=100 y, TPO=15 y, L=40 y, and TR=3 y as EBR,H=550 g-CO2e/kWh × [15 y + (100 y – 15 y) × 3 y / 43 y)] / 100 y = 115 g-CO2e/kWh. Similarly, the background emissions from Plant A averaged over 100 years are EBR,L=550 g-CO2e/kWh × [3 y + (100 y – 3 y) × 1 y / 31 y)] / 100 y = 33.7 g-CO2e/kWh. The difference between the two from Equation 3.1, EOC= EBR,H - EBR,L= 81.3 g-CO2e/kWh, is the opportunity cost emissions of Plant B over 100 years. The time lag between planning and operation of a technology includes a development time and construction time. The development time is the time required to identify a site, obtain a site permit, purchase or lease the land, obtain a construction permit, obtain financing and insurance for construction, install transmission, negotiate a power purchase agreement, and obtain permits. The construction period is the period of building the plant, connecting it to transmission, and obtaining a final operating license. The development phase of a coal-fired power plant without carbon capture equipment is generally 1 to 3 years, and the construction phase is another 5 to 8 years, for a total of 6 to 11 years between planning and operation (Jacobson, 2009). No coal plant has been built from scratch with carbon capture, so this could add to the planning-to-operation time. However, for a new plant, it is assumed that the carbon capture equipment can be added during the long planning-to-operation time of the coal plant itself. As such, Table 3.5 assumes the planning-to-operation time of a coal plant without carbon capture is the same as that with carbon capture. The typical lifetime of a coal plant before it needs to be refurbished is 30 to 35 years. The refurbishing time is an estimated 2 to 3 years. No natural gas plant with carbon capture exists. The estimated planning-to-operation time of a natural gas plant without carbon capture is less than that of a coal plant. However, because of the shorter time, the addition of carbon capture equipment to a new natural gas plant is likely to extend its planning-to-operation time to that of a coal plant with or without carbon capture (6 to 11 years). For comparison, the planning-to-operation time of a utility-scale wind or solar farm is generally 3 to 5 years, with a development period of 1 to 3 years and a construction period of 1 to 2 years (Jacobson, 2009). This time applies to both onshore and offshore wind. For example, the 407 MW (49 turbine) Horns Rev 3 offshore wind farm, located in the North Sea off of the west coast of Denmark, required 1 year and 10 months to build (Frangoul, 2019). Wind turbines often last 30 years before refurbishing, and the refurbishing time is 0.25 to 1 year. Table 3.5 provides the estimate opportunity cost emissions of coal and natural gas with carbon capture due to the time lag between planning and operation of those plants relative to wind or solar farms. The table indicates an investment in fossil fuels with carbon capture instead of wind and solar result in an additional 46 to 62 g-CO2e/kWh in opportunity cost emissions from the background grid.

Table 3.5. Total 100-year CO2e emissions from several different energy technologies. The total includes lifecycle emissions, opportunity cost emissions, anthropogenic heat and water vapor emissions, weapons and leakage risk emissions, and emissions from loss of carbon storage in land and vegetation. All units are g-CO2e/kWh-electricity, except the last, column, which gives the ratio of total emissions of a technology to the emissions from onshore wind. CCS/U is carbon capture and storage or use.

Technology aLifecycle emissions

bOpportunity cost

emissions due to delays

cAnthro-pogenic

heat emissions

dAnthro-pogenic

water vapor emissions

eNuclear Weapons

risk or 100-Year CCS/U leakage

risk

fLoss of CO2 due to covering land or clearing

vegetation

gTotal 100-year

CO2e

Ratio of 100-year CO2e to that of wind-

onshore

Solar PV-rooftop 15-34 -12 to -16 -2.2 0 0 0 0.8-15.8 0.1-3.3 Solar PV-utility 10-29 0 -2.2 0 0 0.054-0.11 7.85-26.9 0.91-5.6 CSP 8.5-24.3 0 -2.2 0 to 2.8 0 0.13-0.34 6.43-25.2 0.75-5.3 Wind-onshore 7.0-10.8 0 -1.7 to -0.7 -0.5 to -1.5 0 0.0002-0.0004 4.8-8.6 1 Wind-offshore 9-17 0 -1.7 to -0.7 -0.5 to -1.5 0 0 6.8-14.8 0.79-3.1 Geothermal 15.1-55 14-21 0 0 to 2.8 0 0.088-0.093 29-79 3.4-16 Hydroelectric 17-22 41-61 0 2.7 to 26 0 0 61-109 7.1-22.7 Wave 21.7 4-16 0 0 0 0 26-38 3.0-7.9 Tidal 10-20 4-16 0 0 0 0 14-36 1.6-7.5 Nuclear 9-70 64-102 1.6 2.8 0-1.4 0.17-0.28 78-178 9.0-37 Biomass 43-1,730 36-51 3.4 3.2 0 0.09-0.5 86-1,788 10-373 Natural gas-CCS/U 179-405 46-62 0.61 3.7 0.36-8.6 0.41-0.69 230-481 27-100 Coal-CCS/U 230-935 46-62 1.5 3.6 0.36-8.6 0.41-0.69 282-1,011 33-211

aLifecycle emissions are 100-year carbon equivalent (CO2e) emissions that result from the construction, operation, and decommissioning of a plant. They are determined as follows: Solar PV-rooftop: The range is assumed to be the same as the solar PV-utility range, but with 5 g-CO2/kWh added to

both the low and high ends to account for the use of fixed tilt for all rooftop PV versus the use of some tracking for utility PV.

Solar PV-utility: The range is derived from Fthenakis and Raugei (2017). It is inclusive of the 17 g-CO2/kWh mean for CdTe panels at 11 percent efficiency, the 27 g-CO2e/kWh mean for multi-crystalline silicon panels at 13.2 percent efficiency, and the 29 gCO2e/kWh mean for mono-crystalline silicon panels at 14 percent efficiency. The upper limit of the range is held at the mean for multi-crystalline silicon since panel efficiencies are now much higher than 13.2 percent. The lower limit is calculated by scaling the CdTe (Cadmium Telluride) mean to 18.5 percent efficiency, its maximum in 2018.

CSP: The lower limit CSP lifecycle emission rate is from Jacobson (2009). The upper limit is from Ko et al. (2018). Wind-onshore and wind-offshore: The range is derived from Kaldelis and Apostolou (2017). Geothermal: The range is from Jacobson (2009) and consistent with the review of Tomasini-Montenegro et al.

(2017). Hydroelectric and wave: From Jacobson (2009). Tidal: From Douglass et al. (2008). Nuclear: The range of 9-70 g-CO2e/kWh is from Jacobson (2009), which is within the Intergovernmental Panel on

Climate Change (IPCC)’s range of 4-110 g-CO2e/kWh (Bruckner et al., 2014), and conservative relative to the 68 (10-130) g-CO2e/kWh from the review of Lenzen (2008) and the 66 (1.4-288) g-CO2e/kWh from the review of Sovacool (2008).

Biomass: The range provided is for biomass electricity generated by forestry residues (43 gCO2e/kWh), industry residues (46), energy crops (208), agriculture residues (291), and municipal solid waste (1730) (Kadiyala et al., 2016).

Natural gas-CCS/U: The lower bound is for the CCGT with carbon capture plant from Skone (2015), also provided in Table 3.4. The upper bound is CCGT value without carbon capture, 506 g-CO2e/kWh from Table 3.4, multiplied by 80 percent, which is the percent of CO2e emissions expected to be captured from the Petra Nova facility that will remain in the air over 100 years (Table 3.6).

Coal-CCS/U: The lower bound is for IGCC with carbon capture from Skone (2015). The upper bound is the coal value without carbon capture, 1,168 g-CO2e/kWh from Table 3.6, multiplied by 80 percent, which is the percent of coal lifecycle CO2e emissions from the Petra Nova facility that will remain in the air over 100 years (Table 3.6).

bOpportunity cost emissions are emissions per kWh over 100 years from the background electric power grid, calculated from Equations 3.1 and 3.2 due to (a) the longer time lag between planning and operation of one energy technology relative to another and (b) additional downtime to refurbish a technology at the end of its useful life compared with the other technology. The planning-to-operation times of the technologies in this table are 0.5-2 years for solar PV-rooftop; 2-5 years for solar PV-utility, CSP, wind-onshore, wind-offshore, tidal, and wave; 3-6 years for geothermal; 8-16 years for hydroelectric; 10-19 years for nuclear; 4-9 years for biomass (without CCS/U), and 6-11 years for natural gas-CCS/U and coal-CCS/U (Jacobson, 2009, except rooftop PV and natural gas-CCS/U values are added and solar PV-rooftop is updated here). The refurbishment times are 0.05-1 year for solar PV-rooftop; 0.25-1 year for solar-PV-utility, CSP, wind-onshore, wind-offshore, wave, and tidal; 1-2 years for geothermal and hydroelectric; 2-4 years for nuclear, and 2-3 years for biomass, coal-CCS/U, and natural gas-CCS/U. The lifetimes before refurbishment are 15 years for tidal and wave; 30 years for solar PV-rooftop, solar PV-utility, CSP, wind-onshore, wind-offshore; 30-35 years for biomass, coal-CCS/U, and natural gas-CCS/U; 30-40 years for geothermal; 40 years for nuclear; and 80 years for hydroelectric (Jacobson, 2009). The opportunity cost emissions are calculated here relative to the utility-scale technologies with the shortest time between planning and operation (solar-PV-utility, CSP, wind-onshore, and wind-offshore). The opportunity cost emissions of the latter technologies are, by definition, zero. The opportunity cost emissions of all other technologies are calculated like in Example 3.1 while assuming a background U.S. grid emission intensity equal to 557.3 g-CO2e/kWh in 2017. This is derived from an electricity mix from EIA (2018d) and emissions, weighted by their 100-year GWPs, of CO2, CH4, and N2O from mining, transporting, processing and using fossil fuels, biomass, or uranium. The reason tidal power has opportunity cost emissions although its planning-to-operation time is the same as onshore wind is the shorter lifetime of tidal turbines than wind turbines. Thus, tidal has more down time over 100 years than do other technologies. See Section 3.2.2.1. The opportunity cost emissions of offshore and onshore wind are assumed to be the same because new projects suggest offshore wind, particularly with faster assembly techniques and with floating turbines, are easier to permit and install now than a decade ago. Although natural gas plants don’t take so long as coal plants between planning and operation, natural gas combined with CCS/U is assumed to take the same time as coal with CCS/U.

cAnthropogenic heat emissions here include the heat released to the air from combustion (for coal or natural gas) or nuclear reaction, converted to CO2e (see Section 3.2.2.2). For solar PV and CSP, heat emissions are negative because these three technologies reduce sunlight to the surface by converting it to electricity. The lower flux to the surface cools the ground or a building below the PV panels. For wind turbines, heat emissions are negative because turbines extract energy from wind to convert it to electricity (Section 3.2.2.3 and Example 3.6). For binary geothermal plants (low end), it is assumed all heat is re-injected back into the well. For non-binary plants, it is assumed that some heat is used to evaporate water vapor (thus the anthropogenic water vapor flux is positive) but remaining heat is injected back into the well. The electricity from all electric power generation also dissipates to heat, but this is due to the consumption rather than production of power and is the same amount per kWh for all technologies so is not included in this table.

dAnthropogenic water vapor emissions here include the water vapor released to the air from combustion (for coal and natural gas) or from evaporation (water-cooled CSP, water-cooled geothermal, hydroelectric, nuclear natural gas, and coal), converted to CO2e (see Section 3.2.2.3). Air-cooled CSP and geothermal plants have zero water vapor flux, representing the low end of these technologies. The high end is assumed to be the same as for nuclear, which also uses water for cooling. The low end for hydroelectric power assumes 1.75 kg-H2O/kWh evaporated from reservoirs at mid to high latitudes (Flury and Frischknecht, 2012). The upper end is 17.0 kg-H2O/kWh from Jacobson (2009) for lower latitude reservoirs and assumes reservoirs serve multiple purposes. For biomass, the number is based only on the water emitted from the plant due to evaporation or combustion, not water to irrigate some energy crops. Thus, the upper estimate is low. The negative water vapor flux for onshore and offshore wind is due to the reduced water evaporation caused by wind turbines (Section 3.2.2.3 and Example 3.6).

eNuclear weapons risk is the risk of emissions due to nuclear weapons use resulting from weapons proliferation caused by the spread of nuclear energy. The risk ranges from zero (no use of weapons over 100 years) to 1.4 g-CO2e/kWh (one nuclear exchange in 100 years) (Section 3.3.2.1). The 100-year CCS/U leakage risk is the estimated rate, averaged over 100 years, that CO2 sequestered underground leaks back to the atmosphere. Section 3.2.2.4 contains a derivation. The leakage rate from natural gas-CCS/U is assumed to be the same as for coal-CCS/U.

fLoss of carbon, averaged over 100 years, due to covering land or clearing vegetation is the loss of carbon sequestered in soil or in vegetation due to the covering or clearing land by an energy facility; by a mine where the fuel is extracted from (in the case of fossil fuels and uranium); by roads, railways, or pipelines needed to transport the fuel; and by waste disposal sites. No loss of carbon occurs for solar PV-rooftop, wind-offshore, wave, or tidal power. In all remaining cases, except for solar PV-utility and CSP, the energy facility is assumed to replace grassland with the organic carbon content and grass content as described in the text. For solar PV-utility and CSP, it is assumed that the organic content of both the vegetation and soil are 7 percent that of grassland because (a) most all CSP and many PV arrays are located in deserts with low carbon storage and (a) most utility PV panels and CSP mirrors are elevated

above the ground. For biomass, the low value assumes the source of biomass is industry residues or contaminated wastes. The high value assumes energy crops, agricultural residues, or forestry residues. See Section 3.2.2.5.

gThe total column is the sum of the previous six columns. 3.2.2.2. Anthropogenic Heat Emissions Anthropogenic heat emissions were defined in Section 1.2.3 to include the heat released to the air from the dissipation of electricity; from the dissipation of motive energy by friction; from the combustion of fossil fuels, biofuels and biomass for energy; from nuclear reaction; and from anthropogenic biomass burning. Jacobson (2014) provide the relative contributions of different energy generating technologies to worldwide anthropogenic heat emissions. Table 3.5 includes the g-CO2e/kWh emissions from heat of combustion (for biomass, natural gas, and coal) and from nuclear reaction. However, because the dissipation of the resulting electricity back to heat is due to the consumption rather than production of electricity, that heat release term is not included in the table. In any case, the heat released per unit electricity produced is the same for all technologies. Solar PV and CSP convert solar radiation to electricity, thereby reducing the flux of heat to the ground or to rooftops below PV panels. This is reflected in Table 3.5 as a negative heat flux. Wind turbines also cause a negative heat flux, discussed in Section 3.2.2.3. The CO2e emissions (g-CO2e/kWh) due to the anthropogenic heat flux is calculated for all technologies (including the negative heat fluxes due to solar and wind) as follows: H = ECO2 × Ah / (FCO2 × Gelec) (3.3) where ECO2 is the equilibrium global anthropogenic emission rate of CO2 (g-CO2/y) that gives a specified anthropogenic mixing ratio of CO2 in the atmosphere, FCO2 is the direct radiative forcing (W/m2) of CO2 at the specified mixing ratio, Ah is the anthropogenic heat flux (W/m2) due to a specific electric power producing technology, and Gelec is the annual global energy output of the technology (kWh/y). The idea behind this equation is that the current radiative forcing (W/m2) in the atmosphere due to CO2 can be maintained at an equilibrium CO2 emission rate, ECO2 = cCO2C/tCO2 (3.4) where cCO2 (ppmv) is the specified anthropogenic mixing ratio that gives the current CO2 radiative forcing, C is a conversion factor (8.0055×1015 g-CO2/ppmv-CO2), and tCO2 is the data-constrained e-folding lifetime of CO2 against loss by all processes. As of 2019, tCO2 is ~50 years but increasing over time (e.g., Jacobson, 2012a). Equation 3.4 is derived by noting that the time rate of change of the atmospheric mixing ratio of a well-mixed gas, such as CO2 is simply, dc/dt = E – cC/t. In steady state, this simplifies to E=cC/t. Scaling the ratio of this equilibrium CO2 emission rate to the radiative forcing of CO2 by the ratio of the anthropogenic heat flux to the electricity generation per year producing that heat flux, gives Equation 3.3, the CO2e emission rate of the heat flux. Thus, Equation 3.3 accounts for the emission rate of CO2 needed to maintain a mixing ratio of CO2 in the air that gives a specific radiative forcing. It does not use the present day emission rate because that results in a much higher CO2 mixing ratio than is currently in the atmosphere because CO2 emissions are not in equilibrium with the CO2 atmospheric mixing ratio. Equation 3.3 requires a constant emission rate that

gives the observed mixing ratio of CO2 for which the current direct radiative forcing applies. Similarly, the energy production rate in Equation 3.3 gives a consistent anthropogenic heat flux. Finally, whereas radiative forcing is a top-of-the-atmosphere value (and represents changes in heat integrated over the whole atmosphere) and heat flux is added to the bottom of the atmosphere, they both represent the same amount of heat added to the atmosphere. In fact, because the anthropogenic heat flux adds heat to near-surface air, it has a slightly greater impact on surface air temperature per unit radiative forcing than does CO2. For example, the globally averaged temperature change per unit direct radiative forcing for CO2 is ~0.6 K/(W/m2) (Jacobson, 2002), whereas the temperature change per unit anthropogenic heat plus water vapor flux is ~0.83 K/(W/m2) (Jacobson, 2014). As such, the estimated CO2e values for heat fluxes in particular in Table 3.5 may be slightly underestimated. Example 3.2. Calculate the carbon equivalent heat emissions for coal and nuclear power worldwide. In 2005, the anthropogenic flux of heat (aside from heat used to evaporate water) from all anthropogenic heat sources worldwide was Ah=0.027 W/m2 (Jacobson, 2014). Assume the percent of all heat from coal combustion was 4.87 percent and from nuclear reaction was 1.55 percent. Estimate the CO2e emissions corresponding to the coal and nuclear heat fluxes given the energy generation of Gelec=8.622×1012 kWh/y from coal combustion and 2.64×1012 kWh/y from nuclear reaction. Assume an anthropogenic CO2 direct radiative forcing of FCO2=1.82 W/m2, which corresponds to an anthropogenic mixing ratio of CO2 of cCO2=113 ppmv (Myhre et al., 2013). Also assume a CO2 e-folding lifetime of tCO2=50 years. Solution: From Equation 3.4, the equilibrium emission rate of CO2 giving the anthropogenic mixing ratio is ECO2=1.809×1016 g-CO2/y. Multiplying the total anthropogenic heat flux by the respective fractions of heat from coal combustion and nuclear reaction gives Ah=0.00132 W/m2 for coal and 0.00042 W/m2 for nuclear. Substituting these and the other given values into Equation 3.3 gives H = 1.52 g-CO2e/kWh for coal and 1.57 g-CO2/kWh for nuclear. Example 3.3. Calculate the carbon-equivalent negative heat emissions of a solar PV panel. Solar panels convert about 20 percent of the sun’s energy to electricity, thereby reducing the flux of sunlight to the ground. What is the reduction in heat flux (W/m2) per kWh/y of electricity generated by a solar panel and what is the corresponding CO2e emission reduction? The surface area of the Earth is 5.092×1014 m2. Solution: If a solar panel produces Gelec=1 kWh/y of electricity, the panel prevents exactly that much solar radiation from converting to heat compared with the sunlight otherwise hitting an equally reflective surface. Eventually, the electricity converts to heat as well (as does the electricity from all electric power generators). However, other electric power generators do not remove heat from the sun on the same timescale as solar panels do. Multiplying the avoided heat (-1 kWh/y) by 1,000 W/kW and dividing by 8760 h/y and by the area of the Earth gives Ah=-2.24×10-16 W/m2. Substituting this, Gelec=1 kWh/y, and ECO2 and FCO2 from Example 3.2 into Equation 3.3 gives H=-2.23 g-CO2e/kWh. Finally, for hydropower, evaporation of water vapor at the surface of a reservoir by the sun increases anthropogenic water vapor emissions (Section 3.2.2.3). Because evaporation requires energy, it cools the surface of the reservoir. The energy used to evaporate the water becomes embodied in latent heat carried by the water vapor. However, the water vapor eventually condenses in the air (forming clouds), releasing the heat back to the air. As a result, warming of the air offsets cooling at the surface, so hydropower causes no net anthropogenic heat flux. On the other hand, water vapor is a greenhouse gas, resulting in a net warming of the air due to evaporation. This warming is accounted for in the next section.

3.2.2.3. Anthropogenic Water Vapor Emissions Fossil fuel, biofuel, and biomass burning release not only heat, but also water vapor. The water vapor results from chemical reaction between the hydrogen in the fuel and oxygen in the air. In addition, coal, natural gas, and nuclear plants require cool liquid water to re-condense the hot steam as it leaves a steam turbine. This process results in significant water evaporating out of a cooling tower to the sky. Many CSP turbines also use water cooling although some use air cooling. Similarly, whereas non-binary geothermal plants and some binary plants use water cooling, thus emit water vapor, binary plants that use air cooling do not emit any water vapor. Further, water evaporates from reservoirs behind hydroelectric power plant dams. Table 1.1 indicates that anthropogenic water vapor from all anthropogenic sources causes about 0.23 percent of gross global warming. On the other hand, wind turbines reduce water vapor, a greenhouse gas, by reducing wind speeds (Chapter 7) (Jacobson and Archer, 2012; Jacobson et al., 2018a). Water evaporation is a function of wind speed (and temperature). In this section, the positive or negative CO2e emissions per unit energy (M, g-CO2e/kWh) due to increases or decreases in water vapor fluxes resulting from an electric power source are quantified. The emissions are estimated with an equation similar to Equation, 3.3, except with the anthropogenic moisture energy flux (Am, W/m2) is substituted for the heat flux: M = ECO2 × Am / (FCO2 × Gelec) (3.5) In this equation, the globally averaged moisture energy flux can be obtained from the water vapor flux per unit energy (V, kg-H2O/kWh) by Am = V × Le × Gelec / (S × Ae) (3.6) where Le=2.465×106 J/kg-H2O is the latent heat of evaporation, S=3.1536×107 seconds per year, and Ae=5.092×1014 m2 is the surface area of the Earth. For water evaporating from a hydropower reservoir, V = 1.75 to 17 kg-H2O/kWh (Table 3.5, footnote c). Combining Equations 3.5 and 3.6 gives the globally averaged CO2e emissions per unit energy due to a positive or negative water vapor flux resulting from an energy generator as M = ECO2 × V × Le / (FCO2 × S × Ae) (3.7) This equation is independent of the total annual energy production (Gelec). Examples 3.4 to 3.6 provide calculations of anthropogenic water vapor fluxes for several of the generators in Table 3.5. Example 3.4. Calculate the carbon-equivalent anthropogenic water vapor emissions from natural gas and nuclear plants. The global anthropogenic water vapor flux from natural gas power plants in 2005 was Am=0.00268 W/m2 and from nuclear power plants was Am=0.000746 W/m2 (Jacobson, 2014). The total energy generation from natural gas use was Gelec=7.208×1012 kWh/y and from nuclear was 2.64×1012 kWh/y. Calculate the CO2e emissions associated with these fluxes. Solution: Substituting ECO2 and FCO2 from Example 3.2 and Am and Gelec provided in the problem into Equation 3.5 gives M=3.69 g-CO2e/kWh for natural gas and 2.81 g-CO2e/kWh for nuclear. Example 3.5. Calculate the carbon-equivalent anthropogenic water vapor emissions from a hydropower reservoir.

If the evaporation rate of water from a hydropower reservoir is V=1.75 kg-H2O/kWh (Flury and Frischknecht, 2012), determine the CO2e emissions of water vapor from the reservoir. Solution: Substituting V into Equation 3.7 with ECO2 and FCO2 from Example 3.2 gives the carbon equivalent emissions due to hydropower reservoir evaporation as M=2.66 g-CO2e/kWh. Wind turbines extract kinetic energy from the wind and convert it to electricity. Kinetic energy is the energy embodied in air due to its motion. For every 1 kWh of electricity produced, 1 kWh of kinetic energy is extracted. Like with all electric power generation, the 1 kWh of electricity eventually converts back to heat that is added back to the air. However, for purposes of assigning CO2e emissions or savings, the conversion of electricity back to heat is not assigned to any particular electric power generator in Table 3.5. However, the addition or extraction of heat and water vapor by the energy technology is. When electricity dissipates to heat, some of that heat returns to kinetic energy. Heat is internal energy, which is the energy associated with the random, disordered motion of molecules. Higher temperature molecules move faster than lower temperature molecules. Some of the internal energy in the air causes air to rise since warm, low-density air rises when it is surrounded by cool, high-density air. To raise the air, internal energy is converted to gravitational potential energy (GPE), which is the energy required to lift an object of a given mass against gravity a certain distance. The lifted parcel is now cooler as a result of giving away some of its internal energy to GPE. Differences in GPE over horizontal distance create a pressure gradient, which recreates some kinetic energy in the form of wind (Section 6.8). In sum, wind turbines convert kinetic energy to electricity, which dissipates to heat. Some of that heat converts to GPE, some of which converts back to kinetic energy. If a wind turbine did not extract kinetic energy from the wind, that energy would otherwise still dissipate to heat due to the wind bashing into rough surfaces, which are sources of friction. But such dissipation would occur over a longer time. However, wind turbines have an additional effect, which is to reduce water vapor, a greenhouse gas. When wind from dry land blows over a lake, for example, the dry wind sweeps water vapor molecules away from the surface of the lake. More water vapor molecules must then evaporate from the lake to maintain saturation of water over the lake surface. In this way, winds increase the evaporation of water over not only lakes, but also over oceans, rivers, streams, and soils. Because a wind turbine extracts energy from the wind, it slows the wind, reducing evaporation of water. By reducing evaporation, wind turbines warm the water or soil near the turbine because evaporation is a cooling process, so less evaporation causes warming. However, because the air now contains less water vapor, less condensation occurs in the air. Since condensation releases heat, less of it means the air cools. In addition, because a wind turbine slows the wind in its wake, it drops the air pressure in its wake as well (Section 6.4). Lower pressure decreases temperature, as evidenced by the increased fog thickness in the wake of wind turbines at the Horns Rev offshore wind farm (Hasager et al., 2013). The increase in fog thickness results from a slight increase in the relative humidity in a turbine’s wake upon a slight drop in temperature, which is due to the drop in pressure. Thus, the surface warming due to wind turbines reducing evaporation is cancelled by the air-cooling due to both lesser atmospheric condensation and lower temperatures in the turbines wake. However, because water vapor is a greenhouse gas, less of it in the air means that more heat radiation from the Earth’s surface escapes to space, cooling the ground, reducing internal energy. Since water vapor stays

in the air for days to weeks, its absence due to a wind turbine reduces heat to the surface over that time more than the one-time dissipation of electricity, created by the wind turbine, increases heat. In sum, wind turbines allow a net escape of energy to space by reducing water vapor. A portion of the lost energy comes from the air’s internal energy, resulting in lower air temperatures. The rest comes from kinetic energy, reducing wind speeds, and from gravitational potential energy, reducing air heights. As such, a new equilibrium is reached in the atmosphere. Section 6.9.1 quantifies the impacts of different numbers of turbines worldwide on temperatures and water vapor. Thus, wind turbines reduce temperatures in the global average by reducing both heat fluxes and water vapor fluxes. Wind turbines do increase temperatures on the ground downwind of a wind farm because they reduce evaporation, but in the global average, this warming is more than offset by atmospheric cooling due to less condensation plus the loss of more heat radiation to space due to the reduction in water vapor caused by wind turbines. The energy taken out of the atmosphere temporarily (because it is returned later as heat from dissipation of electricity) by wind turbines is 1 kWh per 1 kWh of electricity production. The maximum reduction in water vapor, based on global computer model calculations (Chapter 7), due to wind turbines ranges from -0.3 to -1 kg-H2O/kWh, where the variation depends on the number and location of wind turbines. Example 3.6 provides an estimate of the CO2e savings due to wind turbines from these two factors. Example 3.6. Estimate the globally averaged CO2e water vapor and heat emission reductions due to wind turbines. Assuming that wind turbines extract 1 kWh of the wind’s kinetic energy for each 1 kWh of electricity produced, estimate the CO2e savings per unit energy from reduced heat and water vapor fluxes due to wind turbines considering that, when the turbine is not operating, every 1 kWh of kinetic energy in the wind evaporates 0.3 to 1 kg-H2O/kWh and the rest of the energy remains in the atmosphere. Assume the equilibrium emission rate and resulting radiative forcing of CO2 from Example 3.2. Solution: Multiplying the latent heat of evaporation (Le=2.465×106 J/kg) and 1 kWh/3.6×106 J by -0.3 to -1 kg-H2O/kWh gives the reduction in energy available to evaporate water as -0.21 to -0.69 kWh per kWh of electricity-produced. Multiplying 1,000 W/kW and dividing by 8760 h/y and by the area of the Earth, 5.092×1014 m2, gives Am/Gelec = -4.6×10-17 to -1.53×10-16 (W/m2)/(kWh/y). Substituting this and ECO2 and FCO2 from Example 3.2 into Equation 3.5 gives the anthropogenic water vapor energy flux from wind turbines as -0.46 to -1.53 g-CO2e/kWh. The heat flux is the difference between -1 kWh/kWh-electricity and -0.21 to -0.69 kWh/kWh-electricity, which is -0.79 to -0.31 kWh/kWh-electricity. Performing the same calculation as above gives the anthropogenic heat flux from wind turbines as -1.77 to -0.70 g-CO2e/kWh. The total heat plus water vapor energy flux savings due to wind turbines is thus -2.23 g-CO2e/kWh, the same as for solar panels (Example 3.3). 3.2.2.4. Leaks of CO2 Sequestered Underground The sequestration of carbon underground due to CCS or CCU (e.g., from injecting CO2 during enhanced oil recovery) runs the risk of CO2 leaking back to the atmosphere through existing fractured rock or overly porous soil or through new fractures in rock or soil resulting from an earthquake. Here, a range in the potential emission rate due to CO2 leakage from the ground is estimated. The ability of a geological formation to sequester CO2 for decades to centuries varies with location and tectonic activity. IPCC (2005, p. 216) references CO2 leakage rates for an enhanced oil recovery operation of 0.00076 percent per year, or 1 percent over 1,000 years, and CH4 leakage from historical natural gas storage systems of 0.1 to 10 percent per 1,000 years. Thus, while some well-selected sites could theoretically sequester 99 percent of CO2 for 1,000 years, there is no certainty of this since tectonic activity or natural leakage over 1,000 years is not possible to predict. Because liquefied CO2 injected underground

will be under high pressure, it will take advantage of horizontal and vertical fractures in rocks to escape as a gas back to the air. Because CO2 is an acid, its low pH will also cause it to weather rocks over time. If a leak from an underground formation to the atmosphere occurs, it may or may not be detected. If a leak is detected, it may or may not be sealed, particularly if it occurs over a large area. The time-averaged leakage rate of CO2 from a reservoir can be calculated by first estimating how the stored mass of CO2 changes over time. The stored mass (S) of CO2 at any time t in a reservoir, resulting from a constant injection at rate I (mass/y) and e-folding lifetime against leakage, T (years), is S(t)= S(0)e-t/T+TI(1-e-t/T) (3.8)

where S(0) is the stored mass at time t=0. The average leakage rate over t years is then simply the injection rate minus the remaining mass stored mass at time t divided by t years, L(t)= I- S(t)/t (3.9) Once an injection rate and lifetime against leakage are known, the average leakage rate of CO2 from an underground storage reservoir over a specified period can be calculated from Equations 3.8 and 3.9. Example 3.7. Estimating average leakage rates from underground storage reservoirs. Assume a coal-fired power plant has a CO2 emission rate before carbon capture and storage ranging from 790 to 1,017 g-CO2/kWh. Assume also that carbon capture equipment added to the plant captures 90 and 80 percent, respectively, of the CO2 (giving a low and high, respectively, emission rate of remaining CO2 to the air). If the captured CO2 is injected underground into a geological formation that has no initial CO2 in it, calculate a low and high CO2 emission rate from leakage averaged over 100 years, 500 years, and 1,000 years. Assume a low and high e-folding lifetime against leakage of 5,000 years and 100,000 years, respectively. The low value corresponds to 18 percent leakage over 1,000 years, close to that of some observed methane leakage rates. The high value corresponds to a 1 percent loss of CO2 over 1,000 years (e.g., IPCC, 2005). Solution: The low and high injection rates are 790 × 0.9 = 711 g-CO2/kWh and 1,017 × 0.85 = 864.5 g-CO2/kWh, respectively. Substituting these injection rates into Equation 3.8 (using the high lifetime with the low injection rate and the low lifetime with the high injection rate) and the result into Equation 3.9 gives a leakage rate range of 0.36 to 8.6 g-CO2/kWh over 100 years; 1.8 to 42 g-CO2/kWh over 500 years, and 3.5 to 81 g-CO2/kWh over 1,000 years. Thus, the longer the averaging period, the greater the average emission rate over the period due to CO2 leakage. 3.2.2.5. Emissions From Covering Land or Clearing Vegetation Emissions from covering land or clearing vegetation are emissions of CO2 itself due to (a) reducing the carbon stored in soil and in the vegetation above the soil by covering land with impervious material or (b) reducing the carbon stored in vegetation by clearing land so less vegetation grows. When soil is covered with impervious material, such as concrete or asphalt, vegetation can’t grow or decay, and its remains become part of the soil. Similarly, when land is cleared of vegetation, less carbon is stored in the vegetation and below ground. Energy facilities cover land and reduce vegetation. Estimates of the organic carbon stored in grassland and the soil under grassland are 1.15 kg-C/m2 and 13.2 kg-C/m2, respectively (Ni, 2002). Normally, when grass dies, the dead grass contributes to the soil organic carbon. The grass then regrows, removing carbon from the air by photosynthesis. If the soil is instead covered with concrete, the grass no longer exists to remove carbon from the air or store carbon in the soil. However, existing carbon stored underground remains. Some of this is oxidized, though, over time and carried away by ground water.

The carbon emissions due to developing land for an energy facility can be estimated simplistically by first summing the land areas covered by the facility; the mine where the fuel is extracted from (in the case of fossil fuels and uranium); the roads, railways, or pipelines needed to transport the fuel; and the waste disposal site associated with the facility. This summed area is then multiplied by the organic carbon content normally stored in vegetation per unit area that is lost plus the organic carbon content normally stored in soil under the vegetation per unit area that is lost. The latter value can be estimated as approximately one-third the original organic carbon content of the soil. The loss of carbon is then converted to a loss of carbon per unit electricity produced by the energy facility over a specified period of time. For purposes of Table 3.5, this period is 100 years. Example 3.8 provides an example calculation of CO2e emissions from the covering land with an energy facility. Example 3.8. Estimating the loss of carbon stored in vegetation and soil due to an energy facility. Assume a 425 MW coal facility has a 65 percent capacity factor and has a footprint of 5.2 km2, including the land for the coal facility, mining, railway transport, and waste disposal. Calculate the emission rate of CO2 from the soil and vegetation, averaged over 100 years, due to this facility, assuming that it replaces grass and 34 percent of the soil carbon is lost. Solution: The energy generated over one year from this plant is 425 MW × 8760 h/y × 0.65 × 1,000 kW/MW = 2.42×109 kWh/y. Over 100 years, the energy produced is 2.42×1011 kWh. The carbon lost in soil is 0.34 × 13.2 kg-C/m2 = 4.5 kg-C/m2 and that lost from vegetation is 1.15 kg-C/m2, for a total of 5.64 kg-C/m2. Multiplying by 1,000 g/kg and the molecular weight of CO2 (44.0095 g-CO2/mol), then dividing by the molecular weight of carbon (12.0107 g-C/mol) give 20,700 g-CO2/m2. Multiplying this by the land area covered by the facility and dividing by the 100-year energy use gives an emission rate from lost soil and vegetation carbon as 0.44g-CO2/kWh, averaged over 100 years. Because most of the carbon in soil and vegetation is lost immediately, the 100-year average loss of carbon from the soil provided in Table 3.5 underestimates the impact on climate damage of an energy facility that occupies land. Most climate impacts from the loss of carbon will begin when the emissions occur. Thus, for example, the impacts over 10 years of carbon loss in soil are 10 times those in Table 3.5. However, to maintain consistency with the other types of carbon-equivalent emissions in the table, that from soil carbon loss are also averaged over 100 years. 3.2.2.6. Comparison of Coal and Natural Gas with Carbon Capture with Other Energy Technologies Table 3.5 compares the overall 100-year CO2e emissions from coal and natural gas power plants that have carbon capture (CCS or CCSU) with emissions from other electricity generating technologies. The table indicates that coal-CCS/U results in 33 to 211 times the CO2e emissions as onshore wind per unit electricity generated. Natural gas-CCS/U results in 27 to 100 times the emissions as onshore wind. The reasons for the high CO2e emissions of coal and natural gas with carbon capture, are (1) coal and gas plants need 25 to 50 percent more energy to run the carbon capture equipment, and this increases the upstream emissions (fuel mining, transport, and processing) of coal and gas by 25 to 50 percent (Example 3.9), (2) the capture equipment allows 10 to 30 percent of the CO2 in the power plant exhaust to escape (Example 3.9), (3) CO2e emissions from the background grid occur due to the time lag between planning and operation of a coal or gas plant with capture relative to a wind or solar farm, (4) coal and natural gas have heat and water vapor emissions associated with them, (5) some leaks of CO2 occurs once CO2 is sequestered, and (6) coal and gas facilities reduce the storage of carbon in the ground. Table 3.5 provides climate-relevant emissions, but not health-relevant emissions. Air pollution emissions of coal and natural gas without carbon capture are 100 to 400 times those of onshore wind per unit energy. Adding carbon capture to a coal or gas plant increases air pollution emissions another 25 to 50 percent.

The high air pollution and climate-relevant emission rates of coal and natural gas with carbon capture suggest that spending money on them represents an opportunity cost relative to spending money on lower-emitting technologies. Another issue is that, in a future WWS system, the number of hours of fossil fuel use at any given plant decreases, making CCS equipment, which is already costly, even more uneconomical (Lund and Mathiesen, 2012). 3.2.3. Carbon Capture Projects To date, CO2 has been captured and separated primarily from mined natural gas or, in one case, from gasified coal. In all such cases, the CO2 has been used to enhance oil recovery. As of 2019, only two fossil fuel power plants have operated with carbon capture equipment. In both cases, the separated CO2 was used for enhanced oil recovery, and the CCU equipment was installed at high cost. One project experienced equipment problems, resulting in much more CO2 released to the air than anticipated. The other project required a natural gas plant to be built to power the CCU equipment, also resulting in much less benefit than anticipated. Future projects like these must also be in proximity to an oil and gas production field. The first electric power plant with CCU equipment was the Boundary Dam power station in Estevan, Saskatchewan, Canada, which has been operating with CCU equipment on one coal boiler connected to a steam turbine since October 2014. The cost of the retrofit project was $1.5 billion ($13.6 million/MW for a 110 MW turbine). This cost included a $240 million subsidy from the Canadian government and was on top of the original coal plant cost. Whereas half the captured CO2 from the CCU equipment has been sold for enhanced oil recovery, the other half has been released to the air. In addition, since 2016, the CCU equipment has been operating only 40 percent of the time due to design problems. The energy required to run the CCU equipment also results in additional uncaptured CO2 emissions. Mining the coal for the plant results in even more uncaptured emissions. The second plant with CCU equipment was the W.A. Parish coal power plant near Thompsons, Texas. The plant was retrofitted with CCU equipment as part of the Petra Nova project and began using the equipment during January 2017. The CC equipment (240 MW) receives 36.7 percent of the emissions from a 654 MW boiler at the plant. The equipment requires about 0.497 kWh of electricity to run per kWh produced by the coal plant (Table 3.6, Footnote 7). A natural gas turbine with a heat recovery boiler was installed to provide this electricity. A cooling tower and water treatment facility were also added. The retrofit cost $1 billion ($4,200/kW) beyond the coal plant cost (Scottmadden, 2017). The captured CO2 is compressed and piped to an oil field, where it is used to enhance oil recovery. CO2 from the gas turbine is not captured. Natural gas production also has upstream CO2e emissions, including CH4 leaks, which are not captured. Upstream CO2 and CH4 emissions from the coal plant are also uncaptured.

Table 3.6 indicate that, when upstream emissions are excluded, the CCU equipment captures an average of only 55.4 percent of coal combustion CO2 and only 33.9 percent of coal plus gas combustion CO2. Table 3.6 also shows the upstream emissions from the mining and processing of coal and natural gas. When these are accounted for, the CCU equipment reduces coal and gas combustion plus upstream CO2 a net of only 10.8 percent over a 20-year time frame and 20 percent over a 100-year time frame. 20 years is a relevant time frame to avoid 1.5o global warming and resulting climate feedbacks (IPCC, 2018).

When wind, instead of gas, is used to power the CC equipment, CO2e decreases by 37.4 percent over 20 years and 44.2 percent over 100 years compared with no CC (Table 3.6, Figure 1). The CO2e decrease exceeds that in the CCU-gas case because wind powering CC equipment case does not result in any combustion or upstream emissions from wind, as seen in Figure 3.1. However, using the wind electricity that powers the CC equipment instead to replace coal electricity directly at the same plant reduces CO2e by 49.7 percent compared with no CC (Table 3.6, Figure 3.1). It is not 100 percent because only the wind used to run the capture equipment replaces coal. More wind would be needed to replace the whole coal plant. This third strategy is the best for reducing CO2e among the three cases. Using solar PV to replace coal directly results in a similar benefit as using wind. But, CO2e is only part of the story. Because CCU equipment does not capture health-affecting air pollutants, air pollution emissions continue from coal and rise by about 25 percent compared with no capture from the use of natural gas to run the Petra Nova equipment (Table 3.6). Even when wind powers the CC equipment, air pollution from the coal plant continues as before (but not from using the new wind turbine). Only when wind partially replaces the use of coal itself does air pollution decrease by ~50 percent (Table 3.6). Table 3.6. Comparison of relative CO2e emissions, electricity use, and electricity total social costs among three scenarios related to the Petra Nova coal-CCU facility, each over a 20-yr and 100-yr time frame. The first scenario is using natural gas to power the carbon capture (CC) equipment. This is based on data from the Petra Nova facility (EIA, 2017). The second scenario is running the CC equipment with onshore wind instead of natural gas. The third is using the same quantity of wind electricity required to run the CC equipment to instead replace coal electricity from the coal plant. In all cases, the additional energy required to run the CC equipment is equivalent to 49.7 percent of the energy output of the coal plant (Footnote 7). The coal plant has a nameplate capacity of 654 MW, but only 240 MW (36.7 percent) is subject to CC. The numbers in the table are all based on the portion subject to CC. All emission units (including of natural gas emissions) are g-CO2e/kWh-coal-electricity-generation. From Jacobson (2019).

Coal with gas-powered

CC 20 yr

Coal with gas-

powered CC

100 yr

Coal with

wind-powered

CC 20 yr

Coal with

wind-powered

CC 100 yr

Wind used for

CC replacing

coal + remaining

coal 20 yr

Wind used for

CC replacing

coal + remaining

coal 100 yr

a) Upstream CO2 from coal1 97.2 97.2 97.2 97.2 48.9 48.9 b) Upstream CO2e of leaked CH4 from coal2 353 140 353 140 177.6 70.4 c) Coal stack CO2 before capture3 930.6 930.6 930.6 930.6 468.1 468.1 d) Total coal CO2e before capture (a+b+c) 1,381 1,168 1,381 1,168 695 587 e) Remaining stack CO2 after capture4 414.6 414.6 414.6 414.6 -- -- f) CO2 captured from stack (c-e) 516.0 516 516 516 -- -- g) Percent stack CO2 captured (f/c) 55.4% 55.4% 55.4% 55.4% -- -- h) CO2 emissions gas combustion5 200.9 200.9 0 0 0 0 i) Upstream CO2e of CH4 from gas leaks6 139.2 55.03 0 0 0 0 j) Upstream CO2 from gas mining, transport7 26.85 26.85 0 0 0 0 k) Total CO2e emissions (a+b+e+h+i+j) 1,232 934.5 865 652 695 587 l) Percent of coal CO2e re-emitted (k/d)8 89.2% 80.0% 62.6% 55.8% 50.3% 50.3% m) Percent of coal CO2e captured (100-l) 10.8% 20% 37.4% 44.2% 49.7% 49.7% n) Relative CO2e to original (l/100)9 0.892 0.80 0.626 0.558 0.503 0.503 o) Relative air pollution to original10 1.25 1.25 1.0 1.0 0.503 0.503 p) Energy required relative to original11 1.497 1.497 1.497 1.497 1 1 q) Private energy cost/kWh relative to original12 1.74 1.74 1.74 1.74 0.71 0.71 r) Social cost before changes ($/MWh)13 334 334 334 334 334 334 s) Social cost after changes ($/MWh)14 413 399 353 342 189 189 t) Social cost ratio (s/r) 1.24 1.19 1.06 1.02 0.57 0.57

1Coal upstream emissions are estimated as 27 g-CO2/MJ = 97.2 g-CO2/kWh (Howarth, 2014). Upstream emissions include emissions from fuel extraction, fuel processing, and fuel transport. Upstream CO2 emissions (from the portion of the coal plant not replaced) for the wind-replacing some coal cases (last two columns) are the same as in the other cases, but multiplied by 0.503, which equals 1 minus the fraction of coal electricity used to run the carbon capture equipment, which is derived in Footnote 7. Since the electricity used to run the CC equipment is used to replace coal in this case, upstream coal emissions are reduced accordingly.

2For coal, the 100-year CO2e from CH4 leaks is estimated from (Skone, 2015, Slide 17). The emission factor is derived from that number and the 100-year GWP of CH4, 34 from Myhre et al. (2013). The 20-year CO2e is then derived from the resulting emission factor (4.1 g-CH4/kWh) and the 20-year GWP of CH4, 86. Emissions in the wind cases are reduced as described under Footnote 1.

3The average coal stack emission rate for the Petra Nova facility in 2016, prior to the addition of CC equipment, is from EIA (2017). In the wind-replacing-coal cases (last two columns), the emission rate is reduced as described under Footnote 1.

4The coal-stack CO2 remaining after capture is from EIA (2017). 5The natural gas combustion emissions resulting from powering the CC equipment is from EIA (2017). 6Natural gas upstream leaks are obtained by dividing the raw emission rate of CO2 from natural gas for each month

January through June 2017 from EIA (2017) (in kg-CO2/MWh-coal-electricity) by the molecular weight of CO2 (44.0098 g-CO2/mol) to give the moles of natural gas burned per MWh-coal-electricity. Multiplying the moles burned per MWh by the fractional number of moles burned that are methane (0.939) (Union Gas, 2018) and the molecular weight of methane (16.04276 g-CH4/mol) gives the mass intensity of methane in the natural gas burned each month (kg-CH4-burned/MWh-coal-electricity). The upstream leakage rate of methane is then the kg-CH4-burned/MWh-coal-electricity multiplied by L/(1-L), where L=0.023 is the fraction of all methane produced (from conventional and shale rock sources) that leaks (Alvarez et al., 2018), giving the methane leakage rate in kg-CH4/MWh-coal-electricity. This leakage rate is conservative based on a more recent full-lifecycle leakage rate estimate of methane from shale rock alone of L=0.035 (Howarth, 2019). Using the latter estimate would result in CCS/U with natural gas re-emitting even more CO2e than calculated here. Multiplying the kg-CH4/MWh-coal-electricity by the 20- and 100-year GWPs of CH4 (86 and 34, respectively) (Myhre et al., 203) gives the CO2e emission rate of methane leaks each month. The monthly values are linearly averaged over January through June 2017.

7The non-CH4 upstream CO2e emissions rate is estimated as 15 g-CO2/MJ-gas-electricity = 54 g-CO2/kWh-gas-electricity (Howarth, 2014). Multiplying that by 0.497 MWh-electricity from natural gas per MWh-coal-electricity produced gives 26.8 kg-CH4/MWh-coal-electricity. 0.497 MWh-electricity from natural gas per MWh-coal-electricity produced, or 49.7 percent, is calculated by dividing the average gas combustion emission from Petra Nova (200.9 g-CO2/kWh-coal from the present table) by the combustion emissions per unit electricity from a combined cycle gas plant (404 g-CO2/kWh-natural-gas).

8The percent CO2 reemitted for the wind cases (last two columns) equals Row k for the wind cases divided by Row d for either of the non-wind cases.

9CO2e emissions relative to coal with no CC equipment. 10Air pollution emissions relative to coal with no CC equipment. In the natural gas cases, all air pollution from coal

emissions still occurs. Although gas is required to produce 0.497 MWh of electricity for the CC equipment per MWh of coal electricity, gas is assumed to be 50 percent cleaner than coal, so the overall air pollution in this case increases only 25 percent relative to the no CC case. In the wind-CC cases, all upstream and combustion emissions from coal still occur.

11The electricity required (for end-use consumption plus to run the CC equipment) in all CC cases is 49.7 percent higher than with no CC. In the wind-replacing coal case, no electricity is needed to run the CC equipment, but electricity is still needed for end use.

12The private energy cost in all CC cases is assumed to be 74 percent higher than coal with no CC because the CC equipment (including the gas plant) costs $4,200/kW, which represents about 74 percent of the mean capital cost of a new coal plant ($5,700/kW) from Lazard (2018). For simplicity, it was assumed that the cost of a wind turbine running the CC equipment was the same as of a gas turbine running the equipment. In the wind-replacing-coal cases, the cost of coal was assumed to be a mean of c=$102/MWh and of wind, w=$42.5/MWh (Lazard, 2018). The final ratio was calculated as (0.503c+0.497w)/c.

13The social cost before changes is the private energy cost of coal without CCU [$102/MWh from Lazard (2018)] plus air pollution mortality, morbidity, and non-health environmental costs of coal power plant emissions in the U.S. plus the global climate costs of U.S. emissions ($152/MWh) (Jacobson et al., 2017). U.S. coal power plant emissions health costs are estimated as $80/MWh, which is twice the background grid health cost of $40/MWh (Jacobson et al., 2019). In the worldwide average, from the same source, the health cost of background grid emissions is estimated as $169/MWh, so use of the U.S. number here is likely to underestimate the health costs of using carbon capture outside the U.S.

14The social cost after changes is the sum of the private energy cost multiplied by Row q, the air pollution health cost multiplied by Row o, and the climate cost multiplied by Row n.

The equipment cost of new coal and wind electricity in the U.S. are a mean of $102/MWh and $42.5/MWh, respectively (Lazard, 2018). The capital cost of CC equipment, $4,200/kW (Scottmadden, 2017), is about 74 percent the capital cost of a new coal plant ($5,700/kW) (Lazard, 2018), suggesting that new coal plus CCU is 1.74 x $102/MWh / $42.5/MWh = 4.2 times the equipment cost of new wind. Since CC equipment reduces only 10.8% of coal CO2e over 20 yr and 20 percent over 100 yr, the equipment for coal-CCU powered by natural gas alone costs 39 and 21 times that of wind-replacing coal per mass-CO2 removed over 20 and 100 years, respectively. Major additional social costs associated with coal electricity generation are air pollution and climate costs. The health cost of coal emissions in the U.S. is calculated as a mean of $80/MWh, which is much lower than the world average ($169/MWh, Table 3.6, Footnote 13). Since the use of CC equipment requires 50 percent more electricity than the coal plant produces but the health cost of natural gas emissions are about half those of coal, the use of gas to run the CC equipment increases health costs by about 25 percent compared with no capture (Table 3.6, Row o). Mean climate costs of U.S. emissions are estimated as $152/MWh, close to the world mean of $160/MWh (Table 3.6, Footnote 13). CC equipment with natural gas is estimated to reduce this cost by only 10.8 and 20 percent over 20 and 100 years, respectively (Table 3.6, Row n). In sum, the total social cost (equipment plus health plus climate cost) of coal-CCU powered by natural gas is over twice that of wind replacing coal directly (Table 3.6, Figure 3.1). Moreover, the social cost of coal with CC powered by natural gas is 24 percent higher over 20 years and 19 percent higher over 100 years

than coal without CC. Thus, no net social benefit exists of using CC equipment. In other words, from a social cost perspective, using CC equipment powered by natural gas causes more damage than does doing nothing at all. In fact, in order for the social cost of using the CC equipment powered by natural gas to be less than that of doing nothing, the CO2e reemitted by the Petra Nova plant would need to be 37% or less instead of 89.8% over 20 years. However, this is all but impossible, because 59.2% of the re-emissions is due to upstream coal and gas emissions and natural gas combustion emissions, so little to do with how effective the CC equipment is at capturing carbon. In other words, even if the CC equipment captured 100% of the stack CO2, which no-one is proposing is feasible, the reemissions would still be 59.2%. As such, the data indicate that no technological improvement will result in the social cost of using CC equipment powered by natural gas being less than that of not using the equipment.

When wind powers CC equipment, the social costs are still 6 and 2 percent higher over 20 and 100 years, respectively, than not using CC (Table 3.6, Figure 3.1). Although wind-powering-CC decreases CO2e, thus climate cost, compared with coal without CC, wind-CC allows the same air pollution emissions from coal as no CC, and the cost of the wind plus CC equipment outweighs the CO2e cost reduction (Figure 3.1). Only when wind replaces coal electricity production directly does the total social cost drop 43 percent compared with no CC (Table 3.6). This is the best scenario. A similar benefit occurs if wind replaces natural gas and no CC is used. When CC is powered by wind, it is theoretically possible, albeit challenging, to reduce the total social cost below that of no CC. However, it is impossible to reduce the total social cost below that of wind replacing coal electricity directly because wind-powering-CC also incurs a CC equipment cost and never reduces air pollution or mining from coal, whereas wind replacing coal incurs no CC equipment cost and eliminates coal air pollution and mining (Jacobson, 2019). Finally, Figure 3.1 illustrates that CCU powered by wind results in more CO2e than the same wind replacing the coal plant and its upstream emissions. As such, CCU is an opportunity cost not only in terms of total social cost, but also in terms of CO2e emissions. Thus using WWS to replace fossil fuels (or bioenergy) reduces CO2e and social cost over using it to power CCS/U equipment. Figure 3.1. Left: CO2e emissions, averaged over 20 years, from the Petra-Nova coal plant before (No-CCU) and after (CCU-gas) the addition of CCU equipment powered by natural gas. Also shown are emissions when the CCU equipment is powered by wind energy (CCU-wind) and when the portion of wind energy used to power the CCU equipment is instead used only to replace a portion of the coal power (thus some power is generated by coal and some by wind). Blue is upstream CO2e from coal mining and transport aside from CH4 leaks; orange is upstream CO2e from coal mining CH4 leaks; red is coal combustion CO2; yellow is natural gas combustion CO2; green is CO2e from natural gas mining and transport CH4 leaks; and purple is natural gas mining and transport CO2e aside from CH4 leaks. Right: Mean estimate of social costs per unit electricity over 20 years generated by the coal plant (in the first three cases) or the residual coal plant plus replacement wind plant (fourth case) for each of the four cases shown on the left. Light blue is the cost of electricity generation plus CCU equipment; brown is air pollution health cost; and black is 20-year climate cost. All data are from Table 3.6 and Jacobson (2019).

Example 3.9 shows, in more detail, how some of the calculations in Table 3.6 are performed using one out of the six month of data from EIA (2017). Example 3.9. Calculating emission reduction due to coal with carbon capture. According to EIA (2017), emissions of CO2 during January 2016 from the Texas Parish coal power plant, before carbon capture, were 934.4 kg-CO2/MWh. Emissions during January 2017, from the portion of the coal emissions subject to carbon capture, were 242.2 kg-CO2/MWh, for a reduction of 692.2 kg-CO2/MWh. However, the natural gas plant needed to run the carbon capture equipment itself emitted 271.9 kg-CO2/MWh-coal-electricity. In addition, coal upstream emissions were 97.2, 353, and 140 kg-CO2e/MWh-coal-electricity for CO2 from coal mining, CH4 leaks from coal mining over 20 years, and CH4 leaks from coal mining over 100 years, respectively. The non-CH4 upstream emissions from natural gas required for the capture equipment were 36.3 kg-CO2/MWh-coal-electricity. First, estimate the upstream CO2e emissions from CH4 leaks associated with mining, transporting, and processing the natural gas used to run the gas turbine. Then, calculate the overall 20-year and 100-year CO2e of the upstream plus stack emissions from the facility after carbon capture. Finally, what percent of the CO2e upstream plus stack emissions from the facility continue to be emitted over a 20 year and a 100 year time horizon after carbon capture? Assume natural gas contains a 93.9 percent mole fraction of methane, and the upstream leakage rate of natural gas is 2.3 percent (Alvarez et al., 2018). Solution: Dividing the combustion emission rate of CO2 from natural gas, 271.9 kg-CO2/MWh-coal-electricity, by the molecular weight of CO2 (44.0098 g-CO2/mol) gives the moles of natural gas burned. Multiplying the moles burned by the fractional number of moles burned that are methane (0.939) and the molecular weight of methane (16.04276 g-CH4/mol) gives the mass intensity of methane in the natural gas burned, 93.1 kg-CH4-burned/MWh-coal-electricity. The upstream leakage rate of methane is then 93.1 * 0.023 / (1-0.023) = 2.19 kg-CH4/MWh-coal-electricity. Multiplying by the 20- and 100-year GWPs of CH4 (86 and 34, respectively) from Table 1.2 gives CO2e emissions of the methane leaks as 188.4 and 74.5 kg-CO2e/MWh-coal-electricity, respectively. Adding the upstream CO2+CH4 emissions to the natural gas stack emissions gives 20- and 100-year CO2e emissions from the gas turbine as 497 and 382 kg-CO2e/MWh-coal-electricity, respectively. Adding these emissions to the coal upstream emissions and uncaptured coal emissions gives the 20- and 100-year CO2e emissions from the gas turbine plus coal plant after capture as 1,189 and 862 kg-CO2e/MWh-coal-electricity, respectively. The coal stack plus upstream emissions before capture were 1,385 and 1,172 kg-CO2e/MWh-coal-electricity, respectively. As such, averaged over 20 years, 1,189 / 1,385 = 85.8 percent of the original CO2e from the coal plant and its upstream emissions remain in the air; Over 100 years, 73.6 percent remain in the air. These re-emissions are on top of downstream leaks that may occur with the captured CO2. Example 3.10 illustrates that, because coal with CCS/U is (a) expensive, (b) results in more air pollution emissions than coal without CCS/U, and (c) only modestly decreases CO2 emissions, its social cost is more

than 12 times that of wind energy providing the same energy. In addition, the energy cost is 4.2 times that of a wind turbine to produce the same energy. Example 3.10. Calculating the cost to society of using coal with CCS instead of wind. Estimate the energy plus health plus climate change cost of a new coal plant with CCS versus that of wind energy under the following assumptions. The cost of wind energy is 4.25 ¢/kWh (Table 7.9), the cost of a new coal plant is 10.2 ¢/kWh (Table 7.9), the cost of CCS equipment is 7.5 ¢/kWh, the average global health cost of coal pollution is 16.9 ¢/kWh (Table 7.11), and the average global climate cost of coal pollution is 16 ¢/kWh (Table 7.11). Also assume that the CCS equipment requires 25 percent more energy thus increases all emissions by 25 percent. Finally, assume that the CCS equipment reduces the overall CO2 emission by 15 percent compared with before CCS equipment is added. Solution: The social cost of the coal plant is the energy plus health plus climate cost of the plant. In this case, the energy cost of the plant plus equipment is 10.2 + 7.5 = 17.7 ¢/kWh. The health cost is 1.25 × 16.9 ¢/kWh = 21.1 ¢/kWh. The climate cost is 0.85 × 16 ¢/kWh = 13.6 ¢/kWh. Adding these three together gives 52.4 ¢/kWh. Dividing this by the cost of wind, 4.25 ¢/kWh, gives 12.3. Thus, the social cost of coal-CCS in this case is 12.3 times that of wind. The private energy cost of coal-CCS is 4.2 times that of wind.

Tables 3.6 suggests little carbon benefit of and greater air pollution damage from CCS/U powered by natural gas before considering the disposition of the captured CO2. Two reasons for this, aside from the additional combustion emissions of the natural gas turbine, are the upstream coal and gas emissions and the air pollution resulting from the additional gas mining and use. The results here are independent of the fate of the CO2 after it leaves the CC equipment, thus apply to CCS/U with bioenergy (e.g., BECCS/U) or cement manufacturing. The CCS/U equipment always requires energy. If the energy comes from a fossil fuel, mining and combustion emissions from the fuel cancel most CO2 captured. If it comes from a renewable, the renewable will not be able to displace fossil emissions, increasing those emissions. In all cases, air pollution increases. When the fate of captured CO2 is considered, the problem may deepen. If CO2 is sealed underground without leaks, little added emissions occur. If the captured CO2 is used to enhance oil recovery, its current major application, more oil is extracted and burned, increasing combustion CO2, some leaked CO2, and air pollution. If the captured CO2 is used to create carbon-based fuels to replace gasoline and diesel, energy is still required to produce the fuel, the fuel is still burned in vehicles (creating pollution), and little is captured CO2 to produce the fuel with. A third proposal is to use the CO2 to produce carbonated drinks. However, along with the issues previously listed, most CO2 in carbonated drinks is released to the air during consumption. In sum, CCS/U is not close to a zero-carbon technology. For the same energy cost, wind turbines and solar panels reduce much more CO2 while also eliminating fossil air pollution and mining, which CCS/U increases. Renewables further reduce pipelines, refineries, gas stations, tanker trucks, oil tankers, and coal trains, oil spills, oil fires, gas leaks, gas explosions, and international conflicts over energy. CCS/U increases these by increasing energy use. In fact, CCS/U powered by either fossils or renewables always increases total social costs relative to using renewables to eliminate fossil fuel and bioenergy power generation directly.

Table 1.2. E-folding lifetimes, 20-year GWPs, and 100-year GWPs of several global warming agents.

Chemical E-folding lifetime 20-Year GWP 100-Year GWP aCO2 50-90 years 1 1 bBC+POC in fossil fuel soot 3-7 days 2,400-3,800 1,200-1,900 bBC+POC in biofuel soot 3-7 days 2,100-4,000 1,060-2,020 cCH4 12.4 years 86 34 cN2O 121 years 268 298 cCFCl3 (CFC-11) 45 years 7,020 5,350 dCF2Cl2 (CFC-12) 100 years 10,200 10,800 cCF4 (PFC-14) 50,000 years 4,950 7,350 dC2F6 (PFC-116) 10,000 years 8,210 11,100 eTropospheric O3

23 days -- -- fNOx-N < 2 weeks -560 -159 gSOx-S < 2 weeks -1,400 -394

GWP=Global Warming Potential. aThe low-lifetime of CO2 is the data-constrained lifetime upon increasing CO2 emissions from Jacobson (2012a); the

high-lifetime of CO2 is calculated from Figure 9.6, which shows CO2 decreasing by 65 ppmv (from 400 to 335 ppmv) over 65 years upon elimination of anthropogenic CO2 emissions. Since the natural CO2 is 275 ppmv, the anthropogenic CO2 = 400-275=125 ppmv, and the lifetime of anthropogenic CO2 is ~65 y / -ln((125-65) ppmv/125 ppmv) = ~90 years. The GWP of CO2=1 by definition.

bPOC is primary organic carbon co-emitted with black carbon from combustion sources. In the case of diesel exhaust, it is mostly lubricating oil and unburned fuel oil. In all cases, POC includes both absorbing organic (brown) carbon (BrC) and less absorbing organic carbon. Soot particles contain both BC and POC. The lifetime is from Jacobson (2012b) and the GWP is from Jacobson (2010a, Table 4), which accounts for direct effects, optical focusing effects, semi-direct effects, indirect effects, cloud absorption effects, and snow-albedo effects. The GWPs here are the surface temperature response after 20 or 100 years per unit continuous mass emissions (STRE) of BC+POC relative to the same for CO2. STREs are analogous to GWPs (Jacobson, 2010a, Table 4 footnote).

cFrom Myhre et al. (2013) Table 8.7. Results from Etminan et al. (2016) suggest that the 20-y GWP of CH4 may be up to 98. dFrom Myhre et al. (2013) Table 8.A.1. eFrom Myhre et al. (2013), Section 8.2.3.1. Tropospheric ozone is not emitted so does not have a GWP. fFrom Myhre et al. (2013), Table 8.A.3, including aerosol direct and indirect effects. Values are on a per kg nitrogen basis. gFrom Streets et al. (2001) and Jacobson (2002), including aerosol direct and indirect effects. Values are on a per kg

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